By Bob Shively, Enerdynamics’ President
At a recent Enerdynamics seminar, I was asked if capacity markets are necessary in a competitive wholesale market. With Entergy planning to join MISO, competitive wholesale markets are becoming an increasingly large portion of the U.S. electric business, so it is worthwhile to address this question for all of our readers.
A key principle for design and operation of electric infrastructure is to ensure a high level of reliability. One key factor is ensuring there is enough generation available to cover demand peaks. Under the traditional market design of a vertically integrated monopoly utility, sufficient generation capacity is ensured by a regulatory requirement called resource adequacy.
Utilities are required to file resource plans with the state. These plans describe how the utility will serve projected demand peaks and propose any necessary new construction to cover load growth. State regulators review the plans and approve construction of new generation as needed. The costs of new units are put into utility ratebases. Thus, the costs plus a reasonable profit for the utility are paid by customer rates. This process generally works well from a reliability standpoint, and capacity-related power outages have become rare.
But with the movement to competitive wholesale markets run by an ISO, states that broke up the vertically integrated utility no longer have control over generation construction. New generation is built by merchant generators who only build new units when they believe market power prices will support a solid return for shareholders. And if they make a mistake and build unneeded capacity, shareholders – not ratepayers – are on the hook for unrecovered costs.
For baseload units that run most hours of the year, competitive markets are friendly. The units run and get paid the market price, which usually provides a profit since the market energy price is determined by the most expensive unit dispatched. The issue becomes more critical when a market requires new peaking units. These units may only run 100 hours out of the year, and in a cool summer they may not run at all. That means if the unit owners are solely dependent upon energy revenues, those units will be losers in many years. While they may make high profits when prices spike during shortages, such opportunities may be few and far between.
The alternative is to provide an additional revenue stream through a capacity market in which generators are paid up front to be available should the market need their capacity at some point during the year. With this revenue stream, new capacity can get financing to build, and shareholders are assured of at least getting some return on their investment.
Regions like PJM, New York, and New England where capacity has been tight have relied on capacity markets. Others that went into deregulation with significant capacity overhangs such as MISO and ERCOT have gotten by with just energy markets. And California, after finding its energy-only market resulted in rolling blackouts, returned to state-run resource adequacy.
So are capacity markets necessary? I’d say that unless you have a market mechanism that allows state-run resource adequacy to ensure capacity, they eventually are necessary. And even where state regulation is available, I’d contend that competitive capacity markets are a better way to ensure capacity than depending on regulators to decide what gets built.